1. Technical Field
This disclosure generally relates to oil and gas well drilling and the subsequent investigation of subterranean formations surrounding the well. More particularly, this disclosure relates to “field joints,” which are connections for transferring auxiliary fluids and electronic signals/power between components of a downhole tool.
2. Description of the Related Art
Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil and gas, as well as other desirable materials that are trapped in geological formations in the Earth's crust. A well is drilled into the ground and directed to the targeted geological location from a drilling rig at the Earth's surface. The well may be formed using a drill bit attached to the lower end of a “drill string.” Drilling fluid, or “mud,” is typically pumped down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit, and it carries drill cuttings back to the surface in the annulus between the drill string and the wellbore wall.
For successful oil and gas exploration, it is advantageous to have information about the subsurface formations that are penetrated by a wellbore. For example, one aspect of standard formation testing relates to the measurements of the formation pressure and formation permeability. Another aspect of standard formation resting relates to the extraction of formation fluid for fluid characterization, in situ or in surface laboratories. These measurements are useful to predicting the production capacity and production lifetime of a subsurface formation.
One technique for measuring formation and fluid properties includes lowering a “wireline” tool into the well to measure formation properties. A wireline tool is a measurement tool that is suspected from a wireline in electrical communication with a control system disposed on the surface. The tool is lowered into a well so that it can measure formation properties at desired depths. A typical wireline tool may include one or more probe and/or one or more inflatable packer that may be pressed against the wellbore wall to establish fluid communication with the formation. This type of wireline tool is often called a “formation testing tool.” Using the probe, a formation testing tool measure the pressure of the formation fluids and generates a pressure pulse, which is used to determine the formation permeability. The formation testing tool may also withdraw a sample of the formation fluid that is either subsequently transported to the surface for analysis or analyzed downhole.
In order to use any wireline tool, whether the tool be a resistivity, porosity or formation testing tool, the drill string must be removed from the well so that the tool can be lowered into the well. This is called a “trip” uphole. Further, the wireline tools must be lowered to the zone of interest, generally at or near the bottom of the hole. The combination of removing the drill string and lowering the wireline tool downhole is time-consuming and can take up to several hours, depending on the depth of the wellbore. Because of the great expense and rig time required to “trip” the drill pipe and lower the wireline tool down the wellbore, wireline tools are generally used when the information is absolutely need or when the drill string is tripped for another reason, such as changing the drill bit. Examples of wireline formation testers are described, for example, in U.S. Pat. Nos. 3,934,468; 4,860,581; 4,893,505; 4,936,139; and 5,622,223.
To avoid or minimize the downtime associated with tripping the drill string, another technique for measuring formation properties has been developed in which tools and devices are positioned near the drill bit in a drilling system. Thus, formation measurements are made during the drilling process and the terminology generally used in the art is “MWD” (measurement-while-drilling) and “LWD” (logging-while-drilling). A variety of downhole MWD and LWD drilling tools are commercially available.
MWD typically refers to measuring the drill bit trajectory as well as wellbore temperature and pressure, while LWD refers to measuring formation parameters or properties, such as resistivity, porosity, permeability, and sonic velocity, among others. Real-time data, such as the formation pressure, allows the drilling company to make decisions about drilling mud weight and composition, as well as decisions about drilling rate and weight-on-bit, during the drilling process. While LWD and MWD have different meanings to those of ordinary skill in the art, that distinction is not germane to this disclosure, and therefore this disclosure does not distinguish between the two terms. Furthermore, LWD and MWD are not necessarily performed while the drill bit is actually cutting through the formation. For example, LWD and MWD may occur during interruptions in the drilling process, such as when the drill bit is briefly stopped to take measurements, after which drilling resumes. Measurements taken during intermittent breaks in drilling are still considered to be made “while-drilling” because they do not require the drill string to be tripped.
Formation evaluation, whether during a wireline operation or while drilling, often requires that fluid from the formation be drawn into a downhole tool for testing and/or sampling. Various sampling devices, typically referred to as probes, are extended from the downhole tool to establish fluid communication with the formation surrounding the wellbore and to draw fluid into the downhole tool. A typical probe is a circular element extended from the downhole tool and positioned against the sidewall of the wellbore. A rubber packet at the end of the probe is used to create a seal with the wellbore sidewall. Another device that may be used to form a seal with the wellbore sidewall is an inflatable packer. The inflatable packer may be used in a paired configuration that includes two elastomeric rings that radially expand about the tool to isolate a portion of the wellbore therebetween. The rings form a seal with the wellbore wall and permit fluid to be drawn into the isolated portion of the wellbore and into an inlet in the downhole tool.
The various drilling tools and wireline tools, as well as other wellbore tools conveyed on coiled tubing, drill pipe, casing, or other conveyors, are also referred to herein simply as “downhole tools.” Such downhole tools may themselves include a plurality of integrated modules, each for performing a separate function or set of functions, and a downhole tool may be employed alone or in combination with other downhole tools in a downhole tool string.
Modular downhole tools typically include several different types of modules. Each module may perform one or more functions, such as electrical power supply, hydraulic power supply, fluid sampling, fluid analysis, and sample collection. Such modules are depicted, for example, in U.S. Pat. Nos. 4,860,581 and 4,936,139. Accordingly, a fluid analysis module may analyze formation fluid drawn into the downhole tool for testing and/or sampling. This and other types of downhole fluid (other than drilling mud pumped through a drill string) are referred to herein as “auxiliary fluid.” This auxiliary fluid may be transferred between modules of an integrated tool and/or between tools interconnected in a tool string. In addition, electrical power and/or electronic signals (e.g., for data transmission) may also be transferred between modules of such tools. Example of field joints interconnecting tools in a tool string can be found in U.S. Pat. No. 7,191,831, and U.S. Patent App. Pub. No. 2006/0283606, both assigned to the same assignee of the present invention and included herein by reference. Another example of connector can be found in U.S. Pat. No. 6,582,251.
A common issue with field joints used between adjacent modules is contamination of the electrical connection by fluid. Fluid contamination is particularly common when the field joints are broken for transport or reconfiguration after downhole use. Auxiliary fluid and mud may still reside in the internal flow line which, when the field joint is broken, may leak over the exposed end faces of the modules. Also, rain, sea water (in the case of offshore operations) may contaminate the connection the field joint is open on the rig floor. Electrical pins and sockets can become contaminated by the fluid thereby impairing the ability of these components to conduct electricity. Wear-out, contamination of electrical connectors, etc may be so severe that replacement is needed, which typically requires the tool or module to be opened, thereby exposing the internal tool components to the surrounding environment. Additionally, the fluid and electrical connection layout of conventional field joints allows for only a limited number of fluid and electrical connections, thereby limiting the types of modules that may be used in a downhole tool.